This invention relates to a control system for a turbine, and in particular, for a steam turbine. The invention specifically relates to a turbine speed controller that regulates the rotational speed and power output(load) of the turbine, especially during extended periods in which the turbine is required to operate at a frequency other than its normal frequency (speed) set-point.
Industrial and power steam turbines have control systems ("controllers") that monitor and control their operation. Traditionally, these controllers have included a speed/load controller (also referred to as a "droop governor") that maintains the turbine at a predetermined speed (the "speed set-point") prior to synchronization, provides over-speed control for the turbine, and load control when the unit is synchronized. The droop governor generates control signals that regulate the amount of steam flowing through the turbine. The regulation of the amount of steam controls the load when synchronized while the rotational speed of the turbine is in synchronization with the frequency of the electrical system grid.
The turbine is configured to operate at a certain rated speed set-point, which is selected to conform to the rated electrical system frequency. The droop governor reacts when the electrical system frequency deviates from the rated frequency by adjusting the steam inlet valves to adjust the speed of the turbine back to the rated speed set-point. If the turbine speed is substantially greater than its rated speed set-point, the droop governor will close the steam inlet valves.
Industrial and power generation steam turbines are commonly coupled to drive large generators that produce electricity. For example, large turbine-generator units produce electricity for power utilities that distribute electrical power through power grid networks to households, businesses and other power consumers. These electricity consumers generally require constant frequency electricity to power their electrical appliances (such as televisions and clocks); lighting systems; computer, telecommunications and information systems; factory equipment and other electrical systems. The electrical power grid networks usually operate at a predetermined constant power frequencies, such as 50 Hertz (Hz) or 60 Hz. To provide power for such a power grid, the turbine-generator units produce power at a constant frequency, e.g., 50 Hz, that matches the frequency of the grid ("load frequency"). The speed set-point of a steam turbine is selected to drive the generator to produce current at the frequency required by the load, e.g., 50 Hz.
Controllers for steam turbines are well known. An exemplary control system is the General Electric Speedtronic.TM. Mark V Turbine Control System. The SpeedtronicTM controller is a computer system that executes software programs to control the turbine using turbine sensor inputs and instructions from human operators. The commands generated by the controller cause valve actuators on the steam turbine to, for example, control and/or limit the power applied by the turbine to the generator; regulate inlet steam pressure to the turbine; limit inlet steam pressure to the turbine; control the extraction pressure from the turbine; regulate the steam admission control and steam bypass control; provide isochronous speed control, and initiate automatic transfer between operational modes.
Conventional steam turbine controllers perform several steam turbine control functions, including:
Ensuring that the rotational speed and acceleration of the turbine-generator units operate within acceptable limits, especially during start-up, and when (and if) the unit becomes disconnected from the load and would otherwise accelerate too rapidly. PA1 Controlling the position of steam valves that allow steam into the turbine and allow steam to exhaust from the turbine. The steam valve positions control the power output and speed of the turbine. The controller executes signals entered from the operator or an automatic control system to regulate the steam passing through the turbine. In general, the operator sets a speed set-point for the turbine, and a droop governor maintains the speed of the turbine at (or near) that set-point when not synchronized. When the turbine is synchronized with a grid, the controller via its speed control function will help the electrical grid to maintain rated frequency. PA1 Controlling the start-up of the turbine generator unit and its synchronization with a power grid. In particular, power grids operate at certain electrical power frequencies and voltage levels. The turbine generator units must be synchronized with these grid frequencies and voltage levels before they are coupled to the grid. PA1 Providing pressure control of steam at the turbine inlet, at the steam extraction, and for other pressure control functions. PA1 Unloading and securing of the turbine, such as when the turbine is disconnected from the electrical system grid and shut down. PA1 Operating the turbine within certain limits, such as thermal and stress limits. PA1 Providing protection against hazards, such as loss of oil pressure in turbine bearings and high vibration in bearings. PA1 Testing of valves, such as steam inlet and outlet valves, and other vitally-important turbine functions. PA1 Protective emergency overspeed shutdown (trip).
Conventionally, steam turbine controllers have a "speed-loop droop" controller (droop governor) that governs frequency regulation for the turbine-generator unit. The droop governor compensates for load frequency fluctuations and aids the grid in maintaining a relatively constant frequency (and hence rotational speed) of the turbine-generator unit. During a relatively large load rejection in the electrical grid the grid frequency will rise, and the steam turbine droop governor will proportionally close the steam inlet valves to reduce grid frequency to its rated value. As an example of using 5% frequency regulation, an increase of 1% of frequency over its rated value will lead to closing of the inlet steam control valves by 20%. At wide open inlet control valves and rated frequency, a 5% frequency or turbine speed increase will lead to fully closing of the inlet control valves.
Once synchronized with the grid, the rotational speed of the turbine-generator unit is determined by the frequency of the electrical power grid. The controller from the turbine maintains the speed set-point of the turbine at the rated speed-set point. This constant speed set-point for the turbine works well for most loads that have a constant "rated frequency", e.g., 60 Hz in the United States for utility power. The grid frequency typically does not vary and the turbine speed generally is at or near (e.g., within 0.5%) the rated speed set-point. If the load frequency changes, then the set-point is not a good match for the fluctuating load frequency.
If the load frequency does fluctuate and causes the turbine speed to drift, a conventional controller (droop governor) adjusts the valves to bring the turbine back to the set-point. Thus, a fluctuating frequency causes the controller and load to be in conflict. This conflict results in excessive valve operation and other unwanted variables in the operation of the turbine, such as turbine shutdown (if the turbine speed exceeds an over-speed condition, e.g., 105% of speed set-point). Accordingly, conventional turbine-generator units work well with constant frequency loads. They do not tolerate well fluctuations in the operating speed or frequency demands from the load, without moving control valves significantly.
Some electrical grid networks experience relatively-large frequency variations, e.g., plus or minus 5% off rated frequency, that extend over long periods of time, such as several hours. There are also loads on turbine-generator units that do experience relatively long duration, e.g., several hours or more, of operation at frequencies that are lower or higher than their rated frequency.
For example, countries experiencing rapid industrial development may have inadequate power generation utilities. In these countries, industrial power consumers have substantial power demands that vary during the day (as factories cycle through their day-to-day work schedule). During certain periods of a typical work-day, the industrial consumers demand more power than is readily available from the power grid, and cause the power frequency to drift below the rated frequency. During other periods of the day, the power generation utilities are providing more power than their customers require and the utilities allow the power frequency to drift above the rated frequency. Accordingly, the electricity consumers suffer electrical power grids that have relatively-large frequency variations over extended periods of time, such as several hours during high energy usage each day.
In applications where the load frequency fluctuates, the turbine-generator units must match the changing frequency of the load. In the electrical power grid systems with long-periods of frequency drifts, it may be required to maintain the turbine-generator units in operation while the frequency of the load varies by 5% or more from its rated frequency. Thus, the controller of the turbine-generator unit is required to adjust the operation of the unit so as to accommodate these variations in output power frequency.
In the past, compensation for relatively-large variations in load frequency, e.g., plus or minus 5% off rated frequency, has been accomplished by obtaining variances from normal over-speed trip set points, from bucket limitations and from other limitations. These past practices included widening the dead-band of the speed error filter. The dead-band filter causes the controller to ignore small changes in the turbine speed, such as .+-.0.5% from the speed set-point. Widening the dead-band filter to .+-.1.5%, for example, increases the range of fluctuations of the turbine speed for which no compensation is made by the droop governor. However, a wide dead-band filter can cause the droop governor to delay in reacting to fast accelerations in turbine speed such as after a load rejection. Because of the delay, a turbine that experiences a fast acceleration may exceed the overspeed trip setting.
Other prior approaches have involved adjusting the speed set-point of the turbine to match load frequency fluctuations. Repeatedly adjusting the speed set-point is potentially dangerous because it changes the over-speed control response. Other prior approaches have involved providing multiple-sloped characterization of the turbine frequency for use with the droop controller to prevent fast over-speed control response, and add correction of the load reference set-point based on differences between the actual and rated load frequency. These prior approaches have resulted in potentially excessive values of the speed reference and load reference set-points, also referred to as wind-up which leads to loss of over-speed control over ranges of over-frequency. Accordingly, there has been a long-felt need for a steam turbine control system which accommodates relatively-large variations off the rated frequency for the turbine-generator unit.